It is known to conduct fracturing or other stimulation procedures in a wellbore by isolating zones of interest or intervals within a zone) in the hydrocarbon-bearing locations of the wellbore, using packers and the like, and subjecting each isolated zone to treatment fluids, including liquids and gases, at treatment pressures. For example, in a typical fracturing procedure for a cased wellbore, the casing of the well is perforated or otherwise opened to admit oil and/or gas into the wellbore and fracturing fluid is then pumped into the wellbore and through the openings. Such treatment forms fractures and opens and/or enlarges drainage channels in the formation, enhancing the producing ability of the well. For open holes that are not cased, stimulation is carried out directly in the zones or zone intervals.
It is typically desired to stimulate multiple zones in a single stimulation treatment, typically using onsite stimulation fluid pumping equipment and a plurality of downhole tools, including packers and sliding sleeves, each of the packers located at intervals for isolating one zone from an adjacent zone. Sliding sleeves can be located between packers and are selectively actuable through introduction of an actuator into the wellbore to selectively engage one of the sleeves in order to block fluid flow thereby whilst opening the wellbore to the isolated zone uphole from the actuator for subsequent treatment or stimulation. Once the isolated zone has been stimulated, a subsequent ball is dropped to block off a subsequent sleeve, uphole of the previously blocked sleeve, for isolation and stimulation thereabove. The process is continued until all the desired zones have been stimulated. Typically, the actuators are balls that range in diameter from a smallest ball, suitable to travel past uphole sleeves to engage and block the most downhole sleeve, to the largest diameter, suitable for blocking the most uphole packer.
Once the isolated zone has been stimulated, a subsequent ball is dropped to block off a subsequent packer, uphole of the previously blocked packer, for isolation and stimulation thereabove. The process is continued until all the desired zones have been stimulated. Current methods and apparatus typically employ a launcher containing a plurality of actuators to be injected into the wellbore. In typical configurations, actuators are stored in a magazine or several magazines and, when injection of an actuator is desired, introduced into an axial bore axially aligned with the wellbore and pumped down with fracturing fluid.
Using actuator balls for example, while the launcher may have all the sizes of balls need for all the zones, a large and potentially expensive area of risk is the successful selection of the appropriate ball size, successful launch, and actual arrival of the ball at the downhole sleeve. While selection of the correct ball size is typically managed by proper surface procedures, e.g. ball size and launch indicators, an actuator may, once launched, fail to be successfully introduced into the wellbore. Such failures can be due to a variety of reasons, including the actuator becoming stuck in the launcher or the wellhead. The majority of instances where an actuator becomes stuck typically occur before the actuator reaches the wellbore, such as in equipment bores, including those of remote valves, blocks, wellhead components, or other components. For example, at low temperatures, an actuator can become stuck due to moisture in an auxiliary line, remote valve, actuator injector, or other components freezing and obstructing the movement of either the actuator or the mechanisms that move the actuator into the axial bore.
In typical treatment operations, successful transit of a dropped actuator, and actuation of a sleeve, packer, or other downhole tool, is confirmed by monitoring fluid pressure in the tubing string. A pressure spike is indicative of successful actuation by a dropped actuator. A lack of a pressure spike or a pressure spike of lower magnitude than expected is indicative of failed or partial engagement. The actuator can travel kilometers before reaching its target downhole tool. Confirming whether an actuator was successfully launched by waiting for a fluid pressure spike is inefficient, as it requires time and the unnecessary expenditure of fracturing or treatment fluid before failure or success can be determined. There is still a need to more expeditiously and reliably confirm successful actuator release to the wellbore.